Note: Descriptions are shown in the official language in which they were submitted.
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OIL RECOVERY SYSTEM AND METHOD
Field of the Invention
The present invention is directed to a system and a method of recovering oil
from a
subterranean formation, in particular, the present invention is directed to a
method of
enhanced oil recovery from a subterranean formation.
Background of the Invention
A large quantity of oil worldwide is located in heavy oil and bitumen
containing
formations. Not including hydrocarbons in oil shale, it has been estimated
that there are 1.3
to 1.5 trillion cubic meters (8-9 trillion barrels) of heavy oil and bitumen
in-place worldwide.
Heavy oil and bitumen containing formations may occur from the surface of the
earth to a
depth of more than 2000 meters. Heavy oil or bitumen in such formations at a
depth of 75
meters or greater may be recovered by in situ extraction wherein wells are
drilled into the
formation to extract the oil.
In situ extraction of oil from heavy oil or bitumen containing formations is
typically
impeded by the viscosity of the heavy oil or bitumen. Generally, the viscosity
of oil in a
heavy oil or bitumen containing formation is sufficiently great that the oil
does not easily
flow to a well for production.
Thermal methods have been provided for in situ extraction of oil from a heavy
oil or
bitumen containing formation wherein the viscosity of the oil in the formation
is reduced by
heating the oil in the formation, thereby mobilizing the oil in the formation
for production
from the formation via a well. Steam has been used to provide heat in some
thermal methods
for reducing the viscosity of oil in heavy oil or bitumen containing
formations. Steam
assisted gravity drainage (SAGD), cyclic steam stimulation (CSS), and vertical
steam drive
(VSD) are common thermal methods utilized for reducing the viscosity of heavy
oil or
bitumen in a formation by heating the formation with steam that is injected
into the
formation.
Solvents have been used in combination with steam to enhance mobilization of
oil in
a heavy oil or bitumen containing formation for production from the formation.
Low
molecular weight hydrocarbons have been utilized in combination with steam to
reduce the
viscosity of bitumen in situ and enhance recovery of hydrocarbons from a
bitumen-containing
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formation. For example, US Patent No. 6,662,872 provides a process for
reducing the
viscosity of bitumen in a formation and enhancing recovery thereof by co-
injecting steam and
a C1-C8 normal hydrocarbon (e.g. methane, ethane, propane, butane, pentane,
hexane,
heptane, or octane), and US Patent No. 6,708,759 provides a process for
reducing the
viscosity of bitumen in a formation and enhancing recovery thereof that, in
part, requires co-
injecting steam and liquid petroleum condensate comprised of low molecular
weight
paraffinic hydrocarbons. Higher molecular weight hydrocarbons including
aromatic
hydrocarbons have also been used in combination with steam to recover heavy
viscous oils
such as bitumen from an oil-bearing formation. For example, U.S. Patent No.
4,280,559
discloses a process in which steam is injected into a viscous oil-bearing
formation,
hydrocarbons are recovered, then a hydrocarbon solvent containing a low
concentration of
low molecular weight paraffinic hydrocarbons, preferably being light naphtha,
gasoline, and
or aromatic solvents including benzene, toluene, or xylene is injected into
the formation
followed by a second steam injection, and hydrocarbons are then recovered from
the
formation. U.S. Patent No. 3,838,738 further discloses the use of aromatic
hydrocarbons
such as benzene and toluene in combination with steam to recover bitumen from
a bitumen-
containing formation by injecting steam and the aromatic hydrocarbons in a
flow path in the
formation between an injection well and a production well, where the aromatic
hydrocarbons
vaporize in the flow path, and the vaporized hydrocarbons condense and mix
with the
bitumen thereby mobilizing the bitumen for production from the formation
through the
production well. Other solvents such as carbon disulfide or halogenated
hydrocarbons have
also been used in combination with steam to mobilize viscous, heavy oils such
as bitumen in
situ for production from a heavy-oil bearing formation. U.S. Patent No.
3,838,738 further
discloses that carbon disulfide may be used together with steam to mobilize
bitumen for
production from a bitumen-containing formation, and U.S. Patent No. 3,822,748
discloses
that carbon disulfide or halogenated hydrocarbons may be used as petroleum
miscible fluids
together with steam at a steam temperature of less than 121 C (250 F) to
mobilize bitumen
for production from a tar sand formation.
The solvents that have been utilized in combination with steam to mobilize
viscous oil
for production, however, each have attendant difficulties when used to recover
oil from a
heavy oil or bitumen containing formation. A portion of heavy oil or bitumen,
in particular
the asphaltene fraction of the heavy oil or bitumen, is not soluble in low
molecular weight
hydrocarbons, particularly paraffins and most particularly normal paraffins.
or paraffinic low
molecular weight hydrocarbons. As a result, utilization of a low molecular
weight
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hydrocarbon solvent in combination with steam to extract oil from a heavy oil
or bitumen
containing formation 1) leaves a substantial fraction of the oil that is not
soluble in the
solvent in place in the formation, reducing yield; and 2) potentially blocks
mobilization of
producible oil in the formation by precipitating asphaltenes within the
formation. Heavier
hydrocarbons such as aromatic hydrocarbons, light naphtha, and gasoline are
more miscible
with heavy oil and bitumen and do not precipitate asphaltenes from heavy oil
or bitumen
when used as a solvent in conjunction with steam to extract oil from a heavy
oil or bitumen
containing formation, however, due to their higher vaporization temperatures,
a substantial
amount of energy is required to separate these solvents from the produced oil.
Economically,
use of either the light molecular weight hydrocarbons or the heavier
hydrocarbons as a
solvent for use in combination with steam for in situ mobilization and
recovery of oil from a
heavy oil or bitumen containing formation is not practical since the cost and
availability of
the solvent, particularly heavier hydrocarbons, is prohibitive.
Carbon disulfide, while miscible with heavy oil or bitumen, is not
particularly useful
in combination with steam for use in situ for recovery of oil from a heavy oil
or bitumen
containing formation since 1) carbon disulfide is easily hydrolyzed in the
presence of steam
to form hydrogen sulfide and carbon dioxide, thereby souring and acidifying
the formation
and 2) is more dense than oil and water, and falls to the bottom of the
formation.
Halogenated hydrocarbons, also miscible with heavy oil and bitumen, are not
particularly
useful in combination with steam for in situ recovery of oil from a heavy oil
or bitumen
containing formation since halogenated hydrocarbons poison oil hydroprocessing
catalysts
and, therefore, must be completely removed from recovered oil prior to
processing the
recovered oil and because halogenated hydrocarbons are mutagenic.
It is desirable, therefore, to provide an improved process and a system for
recovering
oil from a heavy oil or bitumen containing formation.
Summary of the Invention
In one aspect, the present invention is directed to a method for producing oil
comprising:
providing an oil recovery formulation that comprises at least 15 mol% dimethyl
sulfide, wherein the oil recovery formulation is first contact miscible with
liquid phase
petroleum;
providing steam or hot water having a temperature of at least 80 C;
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introducing the steam or hot water and the oil recovery formulation together
into a
subterranean oil-bearing formation comprising crude oil having a dynamic
viscosity of at
least 1000 mPa s (1000 cP) at 25 C and an API gravity at 15.5 C (60 F) of at
most 20 as
measured in accordance with ASTM D6822, wherein the oil recovery formulation
comprises
at least 15 wt.% of the combined steam and oil recovery formulation introduced
together into
the formation;
contacting the steam or hot water and the oil recovery formulation with the
oil in the
formation; and
producing oil from the formation after introducing the steam or hot water and
the oil
recovery formulation into the formation.
In another aspect, the present invention is directed to a system, comprising:
an oil recovery formulation comprised of at least 15 mol% dimethyl sulfide,
wherein
the oil recovery formulation is first contact miscible with liquid phase
petroleum;
steam or hot water having a temperature of at least 80 C;
a mechanism for introducing the oil recovery formulation and the steam or hot
water
together into a subterranean oil-bearing formation comprising oil having a
viscosity of at
least 1000 mPa s (1000 cP) at 25 C and an API gravity at 15.5 C (60 F) of at
most 20'; and
a mechanism for producing oil from the subterranean oil-bearing formation
subsequent to the introduction of the oil recovery formulation and the steam
or hot water into
the formation.
Brief Description of the Drawings
The drawing figures depict one or more implementations in accordance with the
present teachings, by way of example only, not by way of limitation. In the
figures, like
reference numerals refer to the same or similar elements.
Fig. 1 illustrates an oil production system that may be used to practice the
process of the
present invention.
Fig. 2 illustrates an oil production system that may be used to practice the
process of the
present invention.
Fig. 3 illustrates a processing facility that may be used in the practice of
the process of the
present invention.
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Fig. 4 illustrates an oil production system that may be used to practice the
process of the
present invention, depicting an oil recovery formulation being injected into
an oil-bearing
formation.
Fig. 5 illustrates an oil production system that may be used to practice the
process of the
present invention, depicting production of oil from the formation.
Fig. 6 illustrates an oil production system that may be used to practice the
process of the
present invention.
Fig. 7 is a graph showing petroleum recovery from oil sands at 30 C using
various solvents.
Fig. 8 is a graph showing petroleum recovery from oil sands at 10 C using
various solvents.
Fig. 9 is a graph showing the viscosity reducing effect of increasing
concentrations of
dimethyl sulfide on a West African Waxy crude oil.
Fig. 10 is a graph showing the viscosity reducing effect of increasing
concentrations of
dimethyl sulfide on a Middle Eastern Asphaltic crude oil.
Fig. 11 is a graph showing the viscosity reducing effect of increasing
concentrations of
dimethyl sulfide on a Canadian Asaphaltic crude oil.
Detailed Description of the Invention
The present invention is directed to a method and a system for enhanced oil
recovery
from a subterranean oil-bearing formation comprised of heavy oil, extra-heavy
oil, or
bitumen utilizing steam or hot water and an an oil recovery formulation
comprising at least
15 mol% dimethyl sulfide, wherein the oil recovery formulation is introduced
into the
formation together with the steam or hot water. The oil recovery formulation
is first contact
miscible with liquid phase petroleum, and, in particular, is first contact
miscible with oil in
the subterranean oil-bearing formation.
The steam or hot water introduced into the formation provides heat to the
formation,
rendering the oil therein less viscous. The oil recovery formulation may have
a very low
viscosity so that upon introduction of the oil recovery formulation into the
formation with
steam or hot water the miscible oil recovery formulation may completely mix
with the oil it
contacts to produce a mixture having a significantly reduced viscosity
relative to the oil
initially in place in the formation. The oil recovery formulation may be
vaporized within the
formation by the heat provided by the steam or hot water that is introduced
into the formation
with the oil recovery formulation so the oil recovery formulation may
penetrate the formation
to contact the oil therein and mobilize the oil upon condensation and mixing
with the oil by
reducing the viscosity of the oil. The reduced viscosity mixture may be
mobilized for
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movement through the subterranean formation, where the mobilized mixture may
be
produced from the formation, thereby recovering oil from the formation.
The dimethyl sulfide (also referred to herein as "DMS") of the oil recovery
formulation is particularly useful as a solvent for mobilizing viscous oil in
a formation when
introduced into the formation together with steam or hot water. DMS has a
relatively low
vaporization temperature and may be vaporized upon introduction of the DMS and
steam or
hot water into the formation. DMS is miscible with all portions of the oil
including low
molecular weight paraffins, residue, and asphaltenes and does not precipitate
a portion of the
oil upon contacting the oil, so that all portions of the oil may be recovered
from the
formation. DMS does not impair permeability of the formation by precipitation
of a fraction
of the oil. DMS may be produced with the produced oil and may be easily
recovered from
the produced oil due to the low vaporization temperature of DMS. Furthermore,
unlike
carbon disulfide, DMS is not susceptible to hydrolysis at temperatures at
which the
combination of steam or hot water and DMS may be provided to the formation or
at
temperatures within the formation. DMS is also relatively non-toxic.
Certain terms used herein are defined as follows:
"API gravity" as used herein refers to API gravity at 15.5 C (60 F) as
determined by ASTM
Method D6822.
"Asphaltenes", as used herein, are defined as hydrocarbons that are insoluble
in n-heptane
and soluble in toluene at standard temperature and pressure.
"Operatively fluidly coupled or operatively fluidly connected", as used
herein, defines a
connection between two or more elements in which the elements are directly or
indirectly
connected to allow direct or indirect fluid flow between the elements. The
term "fluid flow",
as used in this definition, refers to the flow of a gas or a liquid; the term
"direct fluid flow"
as used in this definition means that the flow of a liquid or a gas between
two defined
elements flows directly between the two defined elements; and the term
"indirect fluid flow"
as used in this definition means that the flow of a liquid or a gas between
two defined
elements may be directed through one or more additional elements to change one
or more
aspects of the liquid or gas as the liquid or gas flows between the two
defined elements.
Aspects of a liquid or a gas that may be changed in indirect fluid flow
include physical
characteristics, such as the temperature or the pressure of a gas or a liquid;
the state of the
fluid between a liquid and a gas; and/or the composition of the gas or liquid.
"Indirect fluid
flow", as defined herein, excludes changing the composition of the gas or
liquid between the
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two defined elements by chemical reaction, for example, oxidation or reduction
of one or
more elements of the liquid or gas.
"Miscible", as used herein, is defined as the capacity of two or more
substances,
compositions, or liquids to be mixed in any ratio without separation into two
or more phases.
"Petroleum", as used herein, is defined as a naturally occurring mixture of
hydrocarbons,
generally in a liquid state, which may also include compounds of sulfur,
nitrogen, oxygen,
and metals.
"Residue", as used herein, refers to petroleum components that have a boiling
range
distribution above 538 C (1000 F) as determined by ASTM Method D7169.
The oil recovery formulation provided for use in the method or system of the
present
invention is comprised of at least 15 mol% dimethyl sulfide. The oil recovery
formulation
may be comprised of at least 20 mol%, or at least 30 mol%, or at least 50
mol%, or at least 75
mol%, or at least 90 mol%, or at least 99 mol% dimethyl sulfide. The oil
recovery
formulation may consist essentially of dimethyl sulfide, or may consist of
dimethyl sulfide.
The oil recovery formulation provided for use in the method or system of the
present
invention may be comprised of one or more co-solvents that form a mixture with
the
dimethyl sulfide in the oil recovery formulation. The one or more co-solvents
may be
compounds that form an azeotropic mixture with dimethyl sulfide. The one or
more co-
solvents may be compounds that are recovered from the formation upon
production of oil and
the oil recovery formulation from the formation and are separated from the oil
upon
separation of DMS from the oil, for example, compounds that have a
vaporization
temperature near or at the vaporization temperature of DMS, and particularly
compounds that
form an azeotropic mixture with DMS that are recovered from the formation and
are
separated together with DMS from oil produced from the formation. Co-solvent
compounds
that may form an azeotropic mixture with DMS that may be included in the oil
recovery
formulation are pentane, isopentane, 2-methyl-2-butene, and isoprene. The oil
recovery
formulation may be comprised of at least 15 mol% DMS and one or more compounds
selected from the group consisting of pentane, isopentane, 2-methyl-2-butene,
and isoprene.
Less preferably, the oil recovery formulation may also include one or more
other co-
solvent compounds that do not form azeotropic mixtures with DMS. The one or
more other
co-solvents may be selected from the group consisting of o-xylene, toluene,
carbon disulfide,
dichloromethane, trichloromethane, C3-C8 aliphatic and aromatic hydrocarbons,
natural gas
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condensates, hydrogen sulfide, diesel, naphtha solvent, asphalt solvent,
kerosene, and
dimethyl ether.
The oil recovery formulation provided for use in the method or system of the
present
invention is first contact miscible with liquid petroleum compositions,
preferably any liquid
petroleum composition. In liquid phase or in gas phase the oil recovery
formulation may be
first contact miscible with substantially all crude oils including heavy crude
oils, extra-heavy
crude oils, and bitumen, and is first contact miscible in liquid phase or in
gas phase with the
oil in the oil-bearing formation. The oil recovery formulation may be first
contact miscible
with a hydrocarbon composition, for example a liquid phase petroleum, that
comprises at
least 25 wt.%, or at least 30 wt.%, or at least 35 wt.%, or at least 40 wt.%
residue. The oil
recovery formulation may be first contact miscible with liquid phase residue
and liquid phase
asphaltenes in a hydrocarbonaceous composition. The oil recovery formulation
may also be
first contact miscible with C3 to C8 aliphatic and aromatic hydrocarbons
containing less than
wt.% oxygen, less than 10 wt.% sulfur, and less than 5 wt.% nitrogen.
The oil recovery formulation may be first contact miscible with oil having a
moderately high or a high viscosity. The oil recovery formulation may be first
contact
miscible with oil having a dynamic viscosity of at least 1000 mPa s (1000 cP),
or at least
5000 mPa s (5000 cP), or at least 10000 mPa s (10000 cP), or at least 50000
mPa s (50000
cP), or at least 100000 mPa s (100000 cP), or at least 500000 mPa s (500000
cP) at 25 C.
The oil recovery formulation may be first contact miscible with oil having a
dynamic
viscosity of from 1000 mPa s (1000 cP) to 5000000 mPa s (5000000 cP), or from
5000 mPa s
(5000 cP) to 1000000 mPa s (1000000 cP), or from 10000 mPa s (10000 cP) to
500000 mPa s
(500000 cP), or from 50000 mPa s (50000 cP) to 100000 mPa s (100000 cP) at 25
C.
The oil recovery formulation provided for use in the method or system of the
present
invention preferably has a low viscosity. The oil recovery formulation may be
a fluid having
a dynamic viscosity of at most 0.35 mPa s (0.35 cP), or at most 0.3 mPa s (0.3
cP), or at most
0.285 mPa s (0.285 cP) at a temperature of 25 C.
The oil recovery formulation provided for use in the method or system of the
present
invention preferably has a relatively low density. The oil recovery
formulation may have a
density of at most 0.9 g/cm3, or at most 0.85 g/cm3 at 20 C.
The oil recovery formulation provided for use in the method or system of the
present
invention may have a relatively high cohesive energy density. The oil recovery
formulation
provided for use in the method or system of the present invention may have a
cohesive
energy density of at least 1255 Pa, or at least 1340 Pa.
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The oil recovery formulation provided for use in the method or system of the
present
invention preferably is relatively non-toxic or is non-toxic. The oil recovery
formulation may
have an aquatic toxicity of LC50 (rainbow trout) greater than 200 mg/1 at 96
hours. The oil
recovery formulation may have an acute oral toxicity of LD50 (mouse and rat)
of from 535
mg/kg to 3700 mg/kg, an acute dermal toxicity of LD50 (rabbit) of greater 5000
mg/kg, and an
acute inhalation toxicity of LC50 (rat) of 40250 ppm at 4 hours.
In the method of the present invention the oil recovery formulation is
introduced
together with steam or hot water having a temperature of at least 80 C into a
subterranean oil-
bearing formation, and the system of the present invention includes a
subterranean oil-
bearing formation. The subterranean oil-bearing formation comprises crude oil
and may
comprise unconsolidated sand, rock, minerals, and water. The subterreanean oil-
bearing
formation is located beneath an overburden that may extend from the earth's
surface to the
oil-bearing formation. The subterranean oil-bearing formation may be located
at a depth of at
least 75 meters, or at least 100 meters, or at least 500 meters, or at least
1000 meters, or at
least 1500 meters below the earth's surface. The subterranean oil-bearing
formation may
have a permeability of from 0.00001 to 15 Darcy, or from 0.001 to 5 Darcy, or
from 0.01 to 1
Darcy. The subterranean formation may be a subsea formation.
The subterranean oil-bearing formation comprises oil that may be separated and
produced from the formation after contact and mixing with the oil recovery
formulation. The
crude oil of the oil-bearing formation is first contact miscible with the oil
recovery
formulation under formation pressure and temperature conditions as produced
when the oil
recovery formulation is introduced into the formation with steam or hot water,
and is also
first contact miscible with the oil recovery formulation and at standard
temperature and
pressure conditions. The crude oil of the oil-bearing formation is heavy oil,
extra heavy oil,
or bitumen. Heavy oil has an API Gravity of at most 20 . Extra heavy oil and
bitumen each
have an API gravity of at most 10 .
Prior to the introduction of the oil recovery formulation and the steam or hot
water to
the subterranean oil-bearing formation, the crude oil contained in the
formation has a
dynamic viscosity under formation temperature conditions (specifically, at
temperatures
within the temperature range of the formation) of at least 1000 mPa s (1000
cP). The crude
oil contained in the oil-bearing formation may have a dynamic viscosity under
formation
temperature conditions of at least 5000 mPa s (5000 cP), or at least 10000 mPa
s (10000 cP),
or at least 20000 mPa s (20000 cP) or at least 50000 mPa s (50000 cP), or at
least 100000
mPa s. The crude oil contained in the oil-bearing formation may have a
viscosity of from
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1000 to 10000000 mPa s (1000-10000000 cP), or from 5000 to 1000000 mPa s (5000-
1000000 cP), or from 10000 to 500000 mPa s (10000-500000 cP) under formation
temperature conditions. The crude oil contained in the oil-bearing formation
has a dynamic
viscosity of at least 1000 mPa s (1000 cP) at 25 C, and may have a dynamic
viscosity at 25 C
of at least 5000 mPa s (5000 cP), or at least 10000 mPa s (10000 cP), or at
least 20000 mPa s
(20000 cP), or at least 50000 mPa s (50000 cP), or at least 100000 mPa s
(100000 cP). In an
embodiment of the method and the system of the present invention, the
viscosity of the crude
oil contained in the oil-bearing formation is at least partially, or is
substantially, responsible
for immobilizing at least a portion of the petroleum in the formation.
The crude oil contained in the oil-bearing formation may contain a substantial
quantity of high molecular weight hydrocarbons. The crude oil contained in the
oil-bearing
formation may contain at least 25 wt.%, or at least 30 wt.%, or at least 35
wt.%, or at least 40
wt.% of hydrocarbons having a boiling point of at least 538 C (1000 F) as
determined in
accordance with ASTM Method D7169. The crude oil contained in the oil-bearing
formation
may have an asphaltene content of at least 1 wt.%, or at least 5 wt.%, or at
least 10 wt.%.
The subterranean oil-bearing formation may further comprise sand and water.
The
sand may be unconsolidated sand mixed with the oil and water in the formation.
The crude
oil may comprise from 1 wt.% to 20 wt.% of the oil/sand/water mixture; the
sand may
comprise from 80 wt.% to 85 wt.% of the oil/sand/water mixture; and water may
comprise
from 1 wt.% to 20 wt.% of the oil/sand/water mixture. The sand may be coated
with a layer
of water with the oil located in the void space around the wetted sand grains.
The
subterranean oil-bearing formation may also include a small volume of gas such
as methane
or air.
Referring now to Figs. 1 and 2, oil production systems 100 are illustrated
that may be
used to practice one or more embodiments of a steam assisted gravity drainage
(SAGD)
process in accordance with a process of the present invention. An oil
production system 100
includes an oil-bearing formation 105 that may be comprised of oil-bearing
portions 104,
106, and 108 located beneath an overburden 102. The oil production system 100
may include
a first well 132 through which the oil recovery formulation, or components
thereof, and steam
may be injected together into the formation 105, and a second well 112 through
which oil,
water, and at least a portion of the oil recovery formulation may be produced.
The oil
production system may also include a water storage facility 116, an oil
recovery formulation
storage facility 130, and an oil storage facility 134.
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The oil production system 100 may also include a processing facility 110. The
processing facility 110 may include a water processing system 120 and a
separation unit 122.
Referring now to Fig. 3, the water processing system 120 may be comprised of a
water
purification unit 202 comprising one or more particulate filters 204, which
may include an
ultrafiltration membrane; one or more ionic filtration units 206 such as a
nanofiltration
membrane unit and/or a reverse osmosis unit; and/or one or more ion exchange
systems 208
for removing ions from water. Source water may enter the water purification
unit 202
through line 212 and proceed through the particulate filters 204 for removal
of suspended
solids from the source water, and then proceed through the ionic filtration
unit 206 and/or the
ion exchange system 208 for removal of ions, particularly multivalent cations
and sulfate
ions, from the water. The water processing system may also be comprised of a
boiler 210
that is operatively fluidly coupled to the water purification unit 202 via
line 214 to receive
purified water from the water purification unit. The boiler 210 may be
configured to produce
high quality steam having a vapor quality of from 0.7 to 1.0, or to produce
low quality steam
having a vapor quality of from greater than 0.3 to less than 0.7 from the
purified water
produced by the water purification unit, where the steam may be exported from
the water
processing system 120 via line 216.
The separation unit 122 of the processing facility 110 may be designed to
separate oil,
water, and at least a portion of the oil recovery formulation produced from
the formation.
The separation unit 122 may be comprised of a water knockout vessel 230 and a
flash or
distillation unit 232. The water knockout vessel 230 of the separation unit
122 may be
operatively fluidly coupled to the second well by conduit 234 to receive oil,
water, and oil
recovery formulation produced from the formation via the second well. The
produced oil and
produced oil recovery formulation may be separated from produced water in the
water
knockout vessel 230, where the separated produced water may be exported from
the water
knockout vessel and separation unit 122 through conduit 244. Oil/water
separation aids such
as a demulsifier and/or a brine solution may be provided to the water knockout
vessel through
inlet 240 to aid in the separation of the produced oil and produced oil
recovery formulation
from the produced water. The produced oil and produced oil recovery
formulation may be
provided from the water knockout vessel 230 to the flash or distillation unit
232 via conduit
238. The produced oil recovery formulation may be separated from the produced
oil in the
flash or distillation unit, where the flash or distillation unit may be
operated at a temperature
of from 40 C to 80 C and/or at a reduced pressure of from 0.01 MPa to 0.09 MPa
to separate
the oil recovery formulation from the produced oil. The produced oil recovery
formulation
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may include components of the produced oil that have a boiling point at or
near the boiling
point of DMS or that form azeotropic mixtures with DMS, as described above.
The produced
oil may be exported from the flash or distillation unit 232 and the separation
unit 122 through
conduit 242, and the produced oil recovery formulation may be exported from
the flash or
distillation unit 232 and the separation unit 122 through conduit 236.
Referring back to Figs. 1 and 2, the first well 132 and the second well 112
extend
from the surface 140 into one or more of the oil-bearing portions 104, 106,
and 108 of the
subterranean oil-bearing formation 105. A subsurface portion 142 of the first
well 132 and a
subsurface portion 144 of the second well 112 may traverse one or more oil-
bearing portions
of the formation 105. The subsurface portion 144 of the second, producing,
well 112 may be
located below the subsurface portion 142 of the first, injecting, well 132.
The subsurface
portions 142 and 144 of the first and second wells 132 and 112, respectively,
may be
positioned transverse to portions 146 and 148 of the first and second wells
132 and 112,
respectively, that extend from the surface 140 to the respective subsurface
portions 142 and
144 of the wells. The subsurface portion 142 of the first well 132 and the
subsurface portion
144 of the second well 112 may extend horizontally through the formation, and
the
horizontally extending subsurface portion 144 of the second well 112 may
extend
substantially parallel to and below the horizontally extending subsurface
portion 142 of the
first well 132.
The vertical spacing between the horizontal subsurface portion 142 of the
first well
132 and the horizontal subsurface portion 144 of the second well 112 may be
from 2 meters
to 150 meters, or from 5 meters to 100 meters. The horizontal subsurface
portion 142 of the
first well 132 and the horizontal subsurface portion 144 of the second well
112 may have a
length of from 25 meters to 2000 meters, or from 50 meters to 1000 meters, or
from 100
meters to 500 meters. The horizontal subsurface portion 144 of the second well
112 is
preferably as long as, or longer than, the horizontal subsurface portion 142
of the first well
132.
As shown in Fig. 1, a toe section 150 of the subsurface portion 142 of the
first well
132 may be aligned with a heel section 152 of the subsurface portion 144 of
the second well.
Alternatively, as shown in Figure 2, a heel section 154 of the subsurface
portion 142 of the
first well 132 may be aligned with the heel section 152 of the subsurface
portion 144 of the
second well 112. Referring again to Figs. 1 and 2, although the wells 132 and
112 are shown
with an abrupt right angle transition from vertical to horizontal, in some
embodiments wells
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132 and 112 may have a smooth transition from vertical to deviated to
horizontal, for
example with a smooth curved radius.
Referring now to Figs. 1, 2, and 3, in a process of the present invention the
oil
recovery formulation comprising at least 15 mol% DMS is introduced into one or
more oil-
bearing portions 104, 106, or 108 of the oil-bearing formation 105 comprising
heavy oil or
bitumen through the first, injecting, well 132 together with steam. The oil
recovery
formulation and the steam may be introduced into the formation by injecting
the oil recovery
formulation and the steam into the formation 105 through one or more
perforations in the first
well 132. The oil recovery formulation may be provided to the first well 132
for introduction
into the formation from an oil recovery formulation storage facility 130 that
is operatively
fluidly coupled to the first well via conduit 129 to provide the oil recovery
formulation to the
first well. Steam may be provided to the first well 132 for introduction into
the formation
along with the oil recovery formulation by providing source water from the
water storage
facility 116 to the water processing unit 120 of the processing facility 110
via conduit 212,
where particulates and ions are removed from the source water in the water
purification unit
202, steam is formed in the boiler 210 from the purified water, and the steam
is provided to
the first well via conduit 216.
The oil recovery formulation is introduced into the formation together with
the steam,
where the oil recovery formulation comprises at least 5 wt.% of the total
weight of the
combined oil recovery formulation and the steam introduced together into the
formation. The
oil recovery formulation may comprise at least 15 wt.%, or at least 20 wt.%,
or from 5 wt.%
to 80 wt.%, or from 10 wt.% to 75 wt.% of the total weight of the combined oil
recovery
formulation and the steam introduced together into the formation. Sufficient
steam should be
introduced into the formation together with the oil recovery formation to
vaporize at least a
portion of the DMS in the oil recovery formation or to provide sufficient heat
to render
supercritical at least a portion of the DMS in the oil recovery formulation.
Sufficient steam
may be introduced into the formation to heat a portion of the formation and
thereby reduce
the viscosity of a portion of the oil in the formation, where the heat
provided by the steam
may be sensible heat and latent heat.
The oil recovery formulation and the steam may be co-injected into the
formation 105
through the subsurface portion 142 of the first well 132. The subsurface
portion 142 of the
first well 132 may have perforations or openings along the length of the
portion 142 through
which the oil recovery formulation and steam may be injected into the
formation.
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The oil recovery formulation and steam may be injected into the formation 105
under
sufficient pressure to introduce the oil recovery formulation and steam into
the formation.
The oil recovery formulation may be injected into the formation at a pressure
above the initial
pressure of the formation at the injection point, and may be injected at a
pressure ranging
from immediately above the initial pressure of the formation up to the
critical pressure of
steam (22.1 MPa) or up to the critical pressure of DMS (5.7 MPa).
The oil recovery formulation and steam may be injected into the formation 105
at a
temperature sufficient to vaporize the DMS or to render the DMS supercritical
at the
instantaneous formation pressure, where the temperature of the combined oil
recovery
formulation and steam may be controlled by controlling the temperature of the
steam. The
temperature of the steam may be controlled by producing steam of a desired
temperature
from the boiler as conventional in the art. The steam temperature may be
controlled to be
from 100 C to 350 C, or from 200 C to 300 C, or at most 300 C, or at most 250
C, or at most
225 C.
The temperature and pressure of the combined oil recovery formulation and the
steam
introduced into the formation may be controlled so that the DMS of the oil
recovery
formulation may be introduced into the formation as a vapor or as a
supercritical fluid in
accordance with the temperature and pressure phase diagram of DMS as known in
the art.
DMS may be introduced into the formation as a vapor to enhance penetration of
the oil
recovery formulation into the formation, or DMS may be introduced into the
formation as a
supercritical fluid to improve the sweep of the oil recovery formulation
through the
formation.
Upon injection of the oil recovery formulation and steam into the formation
105, the
oil recovery formulation and steam may contact oil within the formation.
Contacting the oil
recovery formulation and steam with oil in the formation may reduce the
viscosity of the oil
by heating the oil with the sensible heat and the latent heat of condensation
of the steam and
by DMS contacting and mixing with the oil to reduce the viscosity of the oil.
The oil in the formation may be mobilized for production by contact with the
oil
recovery formulation and steam introduced into the formation. The reduction of
the oil
viscosity by exchange of thermal energy with the steam and/or by mixing with
the oil
recovery formulation, in particular the DMS, may mobilize the oil contacted by
the steam and
the oil recovery formulation relative to oil initially present in the
formation. The mobilized
reduced viscosity oil may be freed to fall toward the second, production, well
112, from
which the mobilized oil may be produced from the formation. A portion of the
oil recovery
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formulation, including DMS, also may be produced from the formation as a
mixture with the
mobilized oil.
In one embodiment of the process of the present invention, steam, or a
combination of
steam and the oil recovery formulation, may be introduced into the formation
to form a steam
chamber 170 in the formation 105, and after formation of the steam chamber,
the oil recovery
formulation and steam may be introduced into the formation through the steam
chamber to
mobilize and recover oil from the formation. The steam chamber may be formed
by injecting
steam, or the oil recovery formulation together with steam, into the formation
through the
first well 132 and the second well 112. The steam provided from the water
processing
system for injection into the formation to form the steam chamber is
preferably high quality
steam having a vapor quality of from 0.7 to 1.0, preferably from 0.85 to 1.0,
to provide
substantial thermal energy to the formation to reduce the viscosity of the oil
in the formation
around the first and second wells. The injected steam optionally together with
the oil
recovery formulation reduces the viscosity of oil in the immediate vicinity of
the first well
132 and the second well 112. Injection may be stopped from the second well 112
and
reduced viscosity mobilized oil may be produced from the second well. The
steam and
optionally the oil recovery formulation may be injected again through the
second well 112
after recovery of the mobilized oil to reduce the viscosity and mobilize more
oil in the
formation, and then the additional reduced viscosity mobilized oil may be
recovered from the
second well. Injection of steam, optionally together with the oil recovery
formulation,
through the first and second wells 132 and 112 and production of mobilized oil
from the
second well may be continued in this manner until a steam chamber 170 is
formed in the
formation. Thereafter, the oil recovery formulation and the steam may be
injected together
into the formation through the first well 132 and mobilized oil may be
produced from the
second well.
The temperature and pressure of the combined oil recovery formulation and
steam
that are injected into the steam chamber 170 through the first well may be
controlled to
provide the DMS in the oil recovery formulation to the formation in vapor
phase while
providing steam having a vapor quality of from 0.7 to 1.0 from the water
processing system
for introduction to the formation as high quality steam. The high quality
steam may pass
substantially through the steam chamber 170 as vapor and condense at the
oil/steam chamber
interface at the edge of the steam chamber, providing the latent heat of
condensation of the
steam to oil at the edge of the steam chamber, and thereby mobilizing the oil.
The DMS from
the oil recovery formulation may also pass substantially through the steam
chamber as a
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vapor and penetrate the edge of the steam chamber to condense and mix with oil
outside the
steam chamber, thereby reducing the viscosity of the oil and mobilizing the
oil. The oil
mobilized by the steam and by mixing with the oil recovery formulation may
fall through the
formation for production from the formation through the second well, enlarging
the steam
chamber and exposing more oil for production by contact with the steam and the
oil recovery
formulation.
The process of the present invention may also comprise forming a steam chamber
170
in the formation 105; introducing the oil recovery formulation together with
steam into the
steam chamber 170; and recovering residual oil from the steam chamber after
introducing the
oil recovery formulation together with steam into the steam chamber. The steam
chamber
170 may be formed by injecting steam or a combination of steam and the oil
recovery
formulation into the formation as described above for a first period of time.
The resulting
steam chamber has a reduced quantity of oil therein (the "residual oil")
relative to the amount
of oil present in the formation at the boundary of the steam chamber and
portions of the
formation outside of the steam chamber.
The oil recovery formulation together with steam may be injected into the
steam
chamber 170 through the subsurface portion 142 of the first well 132 for a
second time
period, where the second time period commences after the first time period
ends. The
temperature and pressure of the combined oil recovery formulation and steam
that are
injected into the steam chamber 170 through the first well may be controlled
to provide the
DMS in the oil recovery formulation to the formation as a supercritical fluid
while optionally
providing steam having a vapor quality of from 0.3 to less than 0.7 from the
water processing
system for introduction to the formation as low quality steam. The oil
recovery formulation
may contact the residual oil in the steam chamber 170 and mobilize the
residual oil as
described above, where supercritical DMS has a density greater than vapor
phase DMS and
may more effectively sweep the steam chamber for contact and mixing with
residual oil in
the steam chamber than vapor phase DMS. The low quality steam may provide
latent heat of
condensation to the residual oil, also reducing the viscosity of the residual
oil and mobilizing
the residual oil. The mobilized residual oil may fall from the steam chamber
170 to the
second well 112 for production from the formation.
The mobilized oil, water, and oil recovery formulation may be produced from
the
formation through the second well 112 by conventional oil production
processes. The well
112 may include conventional mechanisms for producing oil from a formation,
including lift
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pumps, lift gases, and/or a compressor for injecting gas into the formation to
produce the oil,
water, and oil recovery formulation from the formation.
The oil, water, and oil recovery formulation produced from the formation
through the
second well 112 may be processed and separated. The second well 112 may be
operatively
fluidly coupled to the water knockout vessel 230 of the separation unit 122
via conduit 234.
As described above, the produced oil, produced oil recovery formulation, and
produced water
may be separated in the separation unit 122. The separated produced oil may be
provided
from the flash or distillation unit 232 of the separation unit to the oil
storage facility 134 via
conduit 242. The separated produced water may be provided from the water
knockout vessel
230 of the separation unit 122 to the water storage facility 116 via conduit
244. The
separated oil recovery formulation may be provided from the flash or
distillation unit 232 to
the oil recovery formulation storage facility 130 via conduit 236.
The separated produced oil recovery formulation may be introduced again into
the
formation together with steam to mobilize further oil for recovery from the
formation,
thereby cycling the oil recovery formulation through the formation. The
separated produced
oil recovery formulation may comprise additional hydrocarbons relative to the
oil recovery
formulation initially introduced into the formation. Hydrocarbons that have a
boiling point
near the boiling point of DMS or that form azeotropic mixtures with DMS may be
separated
from the produced oil in the flash or distillation. In particular, pentane,
isopentane, 2-methyl-
2-butene, and isoprene may be separated with DMS from the produced oil.
The process of the present invention may also be utilized in a cyclic steam
stimulation
("CSS") oil recovery process. Referring now to Figs. 4 and 5, an oil
production system
utilizing a single well for injection and production according to a CSS
process in accordance
with the process of the present invention is shown. The system 300 may be
similar in some
respects to the system 100 described above with reference to Figs. 1 and 2 and
with the
processing facility of Fig. 3. Accordingly, the system 300 may be understood
with reference
to Figs. 1, 2, and 3, where like numerals are used to indicate like components
that will not be
described again in detail.
Referring now to Fig. 4, steam or hot water having a temperature of at least
80 C and
an oil recovery formulation comprising at least 15 mol% DMS may be provided.
The oil
recovery formulation and steam or hot water may be injected together into a
formation 105
through well 312. The oil recovery formulation may be provided to the well 312
from an oil
recovery formulation storage facility 130 via conduit 302. Steam may be
provided to the well
312 via a conduit 216 from a water processing system 120 including a water
purification
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system and a boiler for producing steam or water having a temperature of at
least 80 C, or
from 80 C to 100 C, from water provided from a water storage facility 116.
The oil recovery formulation and the steam or hot water may be injected
together into
the formation 105 through the well 312 to contact and mix with oil in the
formation, as shown
by arrows 314. The oil recovery formulation may reduce the viscosity of the
oil upon contact
with the oil, as described above, and thereby mobilize the oil for recovery
from the formation.
The steam or hot water may also reduce the viscosity of the oil by providing
thermal energy
to the oil as described above, mobilizing the oil for recovery from the
formation.
The oil recovery formulation and the steam or hot water may be injected into
the
formation through the well 312 for a first period of time after which
injection of the oil
recovery formulation and steam or hot water may be ceased. The oil recovery
formulation
may be allowed to soak in the formation to mix with the oil therein and reduce
the viscosity
of the oil and mobilize the oil after cessation of injection of the oil
recovery formulation and
steam or hot water into the formation. Steam may be allowed to condense in the
formation
and/or hot water may be allowed to soak in the formation to provide thermal
energy to the oil
therein to reduce the viscosity of the oil and mobilize the oil after
cessation of injection of the
oil recovery formulation and steam or hot water into the formation.
Then, as shown in Fig. 5, the mobilized oil, water, and the oil recovery
formulation
may be produced from the formation through the well 312 for a second time
period, where
the second time period commences after the end of the first time period, and
preferably after
the oil recovery formulation, and optionally hot water, has been allowed to
soak in the
formation, and steam has been allowed to condense in the formation. The
mobilized oil,
water, and oil recovery formulation may be drawn through the formation as
shown by arrows
316 for production from the well. The well 312 may include conventional
mechanisms for
producing oil from a formation, including lift pumps, lift gases, and/or a
compressor for
injecting gas into the formation to produce the oil, water, and oil recovery
formulation from
the formation.
The oil, water, and oil recovery formulation produced from the well 312 may be
separated in the processing facility 110 and stored as described above. The
separated
produced oil recovery formulation may be introduced into the formation again
together with
steam or hot water as described above.
In one embodiment of a CSS process in accordance with the process of the
present
invention, prior to injecting the oil recovery formulation into the formation
and subsequently
recovering mobilized oil, water, and the oil recovery formulation therefrom,
high quality
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steam having a vapor quality of at least 0.7, or at least 0.9, may be produced
by the water
processing system and provided for injection into the formation 105 through
well 312 to
contact and mix and soak with oil in the formation to mobilize the oil, and
then the mobilized
oil may be recovered through well 312. The cycle of injection of high quality
steam into the
formation; contacting, mixing, and soaking the high quality steam with the oil
to mobilize the
oil, and recovery of the mobilized oil from the well may be effected two or
more times prior
to injecting the oil recovery formulation together with steam or hot water
into the formation;
contacting, mixing, and soaking the oil recovery formulation and steam or hot
water with oil
in the formation to mobilize the oil in the formation; and recovering the
mobilized oil from
the well through which the oil recovery formulation and steam or hot water
were injected into
the formation. Use of the oil recovery formulation and steam or hot water
together as
described above after CSS oil recovery using high quality steam enables
recovery of residual
oil in the formation.
The process of the present invention may also be utilized in a vertical steam
drive
("VSD") oil recovery process. Referring now to Fig. 6, an oil production
system 400 is
illustrated that may be used to practice one or more embodiments of a vertical
steam drive
(VSD) process in accordance with the process of the present invention. The
system may be
similar in some respects to the system 100 described above with respect to
Figs. 1 and 2 and
the processing facility 110 as shown in Fig. 3. Accordingly, the system 400
may be
understood with reference to Figs. 1, 2, and 3, where like numerals are used
to indicate like
components that will not be described again in detail.
Referring now to Fig. 6, oil recovery formulation comprising at least 15 mol%
DMS
and steam or hot water having a temperature of at least 80 C are provided for
introduction
into a formation 105 through a first well 432. The oil recovery formulation
may be provided
to the first well 432 from an oil recovery formulation storage facility 130
via conduit 129,
and steam or hot water may be provided to the first well via conduit 216 from
a water
processing system 120 including a water purification system and a boiler for
producing steam
or water having a temperature of at least 80 C from water provided from a
water storage
facility 116.
The oil recovery formulation and steam or hot water may be introduced together
into
the formation 105 through the first well 432 to contact and mix with oil, as
described above,
and thereby mobilize the oil for recovery from the formation. The steam or hot
water may
reduce the viscosity of the oil upon contact by providing thermal energy to
the oil, as
described above, and thereby mobilize the oil for recovery from the formation
105. The oil
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recovery formulation may reduce the viscosity of the oil by mixing with the
oil, as described
above, thereby mobilizing the oil for production from the formation. The steam
or hot water
may also provide thermal energy for vaporizing the DMS of the oil recovery
formulation
within the formation, wherein the vaporized DMS may penetrate the formation
and then
condense and mix with oil in the formation to mobilize the oil.
The volume of the oil recovery formulation and steam or hot water introduced
into the
formation 105 via the first well 432 may range from 0.001 to 10 pore volumes,
or from 0.01
to 5 pore volumes, or from 0.1 to 2 pore volumes, or from 0.2 to 1 pore
volumes, where the
term "pore volume" refers to the volume of the formation that may be swept by
the oil
recovery formulation and steam or hot water between the first well 432 and the
second well
412. The pore volume may be readily determined by methods known to a person
skilled in
the art, for example by modelling studies or by injecting water having a
tracer contained
therein through the formation 105 from the first well 432 to the second well
412.
The mobilized oil may be pushed across the formation 105 from the first well
432 to
the second well 412 as shown by arrows 414 and 416 by further introduction of
more oil
recovery formulation and steam or hot water into the formation or by
introduction of an oil
immiscible drive fluid into the formation subsequent to injection of the oil
recovery
formulation and steam or hot water into the formation.
The oil immiscible drive fluid may be introduced into the formation 105
through the
first well 432 to force or otherwise displace the mobilized oil toward the
second well 412 for
production. The oil immiscible drive fluid may be configured to displace the
mobilized oil
through the formation 105. Suitable oil immiscible drive fluids are not first
contact miscible
or multiple contact miscible with oil in the formation 105. The oil immiscible
drive fluid
may be selected from the group consisting of an aqueous polymer fluid, water,
carbon
dioxide at a pressure below its minimum miscibility pressure, nitrogen at a
pressure below its
minimum miscibility pressure, air, and mixtures of two or more of the
preceding.
Suitable polymers for use in an aqueous polymer fluid may include, but are not
limited to, polyacrylamides, partially hydrolyzed polyacrylamides,
polyacrylates, ethylenic
copolymers, biopolymers, carboxymethylcellulose, polyvinyl alcohols,
polystyrene
sulfonates, polyvinylpyrolidones, AMPS (2-acrylamide-2-methyl propane
sulfonate),
combinations thereof, or the like. Examples of ethylenic copolymers include
copolymers of
acrylic acid and acrylamide, acrylic acid and lauryl acrylate, lauryl acrylate
and acrylamide.
Examples of biopolymers include xanthan gum, guar gum, alginates, and alginic
acids and
their salts. In some embodiments, polymers may be crosslinked in situ in the
formation 105.
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In other embodiments, polymers may be generated ex situ and then injected into
the
formation 105 in an aqueous solution.
The oil immiscible drive fluid may be stored in, and provided for introduction
into the
formation 105 from, an oil immiscible drive fluid storage facility 420 that
may be operatively
fluidly coupled to the first well 432 via conduit 422. The amount of oil
immiscible drive
fluid introduced into the formation 105 should be sufficient to drive the
mobilized oil across
at least a portion of the formation, and preferably is at least 0.2 pore
volumes or at least 0.5
pore volumes, or at least 1 pore volume as measured between the first well 432
and the
second well 412.
If the oil immiscible drive fluid is in liquid phase, the oil immiscible drive
fluid may
have a viscosity of at least the same magnitude as the viscosity of the
mobilized oil at
formation temperature conditions to enable the oil immiscible drive fluid to
drive the
mobilized oil across the formation 105 to the second well 412. The oil
immiscible
formulation may have a viscosity of at least 0.8 mPa s (0.8 cP) or at least 10
mPa s (10 cP), or
at least 50 mPa s (50 cP), or at least 100 mPa s (100 cP), or at least 500 mPa
s (500 cP), or at
least 1000 mPa s (1000 cP), or at least 10000 mPa s (10000 cP) at 25 C. If the
oil immiscible
drive fluid is in liquid phase, preferably the oil immiscible drive fluid may
have a viscosity at
least one order of magnitude greater than the viscosity of the mobilized oil
at formation
temperature conditions so the oil immiscible drive fluid may drive the
mobilized oil across
the formation in plug flow, minimizing and inhibiting fingering of the
mobilized oil through
the driving plug of oil immiscible formulation.
The oil recovery formulation together with steam or hot water and the oil
immiscible
drive fluid may be introduced into the formation 105 through the first well
432 in alternating
slugs. For example, the oil recovery formulation together with steam or hot
water may be
introduced into the formation 105 through the first well 432 for a first time
period, after
which the oil immiscible drive fluid may be introduced into the formation
through the first
well for a second time period subsequent to the first time period, after which
the oil recovery
formulation together with steam or hot water may be introduced into the
formation through
the first well for a third time period subsequent to the second time period,
after which the oil
immiscible drive fluid may be introduced into the formation through the first
well for a fourth
time period subsequent to the third time period. As many alternating slugs of
the oil recovery
formulation together with steam or hot water and the oil immiscible drive
fluid may be
introduced into the formation through the first well as desired.
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Oil may be mobilized for production from the formation 105 via the second well
412
by introduction of the oil recovery formulation together with steam or hot
water and,
optionally, the oil immiscible drive fluid into the formation, where the
mobilized oil is driven
through the formation for production from the second well as indicated by
arrows 416 by
introduction of the oil recovery formulation together with steam or hot water
and optionally
the oil immiscible drive fluid into the formation via the first well 432.
The mobilized oil, water, and oil recovery formulation may be produced from
the
formation 105 through the second well 412 by conventional oil production
processes. The
well 412 may include conventional mechanisms for producing oil from a
formation,
including lift pumps, lift gases, and/or a compressor for injecting gas into
the formation to
produce the oil, water, and oil recovery formulation from the formation. Oil,
water and the
oil recovery formulation produced from the formation may be processed,
separated, and
stored as described above. Produced and separated oil recovery formulation may
be
reintroduced into the formation together with steam or hot water, cycling the
oil recovery
formulation through the formation to reduce the total quantity of oil recovery
formulation
utilized to recover oil from the formation.
In an embodiment of a VSD process in accordance with the process of the
present
invention, the first well 432 may be used for introducing the oil recovery
formulation
together with steam or hot water and, optionally, subsequently the oil
immiscible drive fluid
into the formation 105 and the second well 412 may be used for producing oil,
water, and the
oil recovery formulation from the formation for a first time period; then the
second well 412
may be used for introducing the oil recovery formulation together with steam
or hot water
and, optionally, subsequently the oil immiscible drive fluid into the
formation 105 and the
first well 432 may be used for producing oil, water, and the oil recovery
formulation from the
formation for a second time period; where the first and second time periods
comprise a cycle.
Multiple cycles may be conducted which include alternating the first well 432
and the second
well 412 between introducing the oil recovery formulation together with steam
or hot water
and, optionally, subsequently the oil immiscible drive fluid into the
formation 105, and
producing oil, water, and the oil recovery formulation from the formation,
where one well is
introducing and the other is producing for the first time period, and then
they are switched for
a second time period. A cycle may be from about 12 hours to about 1 year, or
from about 3
days to about 6 months, or from about 5 days to about 3 months. The oil
recovery
formulation together with steam or hot water may be introduced into the
formation at the
beginning of a cycle and the oil immiscible drive fluid may be introduced at
the end of the
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cycle. In some embodiments, the beginning of a cycle may be the first 10% to
about 80% of
a cycle, or the first 20% to about 60% of a cycle, the first 25% to about 40%
of a cycle, and
the end may be the remainder of the cycle.
In one embodiment of a VSD process in accordance with the process of the
present
invention, a fluid flow path between the first well 432 and the second well
412 may be
established prior to introducing the steam or hot water together with the oil
recovery
formulation comprising at least 15 mol% DMS into the formation since
unconsolidated sand
and the viscous crude oil of the formation may impede injection of the oil
recovery
formulation and steam or hot water into the formation. A fluid flow path may
be established
in the formation 105 by injecting steam into the formation or by hydraulic
fracturing. Steam
may be injected to establish a fluid flow path if the injection path from the
first well 432 in
the formation 105 is located in a water saturated zone of the formation. Any
asphaltic or other
hydrocarbon materials located in the water saturated zone may be mobilized by
the steam,
opening a fluid flow path. Alternatively, or in conjunction with injection of
steam into the
formation 105, hydraulic fracturing may be utilized to establish a fluid flow
path from the
first well 432 into the formation, particularly in hydrocarbon saturated zones
of the
formation, where the first well may include a mechanism for hydraulic
fracturing of the
formation. Hydraulic fracturing may be effected in accordance with well known
hydraulic
fracturing techniques. Once a fluid flow path has been established in the
formation 105, a
propping agent may be injected into the flow path to prevent the flow path
from closing,
where the well may have a mechanism for injecting a propping agent into an
established fluid
flow path. Gravel and sand or mixtures thereof may be utilized as propping
agents, where the
propping agent may have a wide distribution of particle sizes to prevent the
tar sand materials
in the formation from flowing into and closing the fluid flow path.
The steam or hot water together with the oil recovery formulation then may be
introduced into the formation 105 through the first well 432 into the
established flow path.
The DMS in the oil recovery formulation may vaporize due to the thermal energy
provided
by the steam or hot water and move upward from the flow path into the
formation where it
may condense and mix with oil to reduce the viscosity of the oil and thereby
mobilize the oil.
The mobilized oil may fall into the flow path and be driven along the flow
path for
production from the second well 412. In an embodiment, alternating slugs of
the oil recovery
formulation together with steam or hot water and an oil immiscible formulation
as described
above are injected into the flow path from the first well, where the oil
immiscible formulation
may drive the mobilized oil along the flow path for production from the second
well.
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EXAMPLE 1
The quality of dimethyl sulfide as an oil recovery agent based on the
miscibility of
dimethyl sulfide with a crude oil relative to other compounds was evaluated.
The miscibility
of dimethyl sulfide, ethyl acetate, o-xylene, carbon disulfide, chloroform,
dichloromethane,
tetrahydrofuran, and pentane solvents with Muskeg River mined oil sands was
measured by
extracting the oil sands with the solvents at 10 C and at 30 C to determine
the fraction of
hydrocarbons extracted from the oil sands by the solvents. The bitumen content
of the
Muskeg River mined oil sands was measured at 11 wt.% as an average of bitumen
extraction
yield values for solvents known to effectively extract substantially all of
bitumen from oil
sands¨in particular chloroform, dichloromethane, o-xylene, tetrahydrofuran,
and carbon
disulfide. One oil sands sample per solvent per extraction temperature was
prepared for
extraction, where the solvents used for extraction of the oil sands samples
were dimethyl
sulfide, ethyl acetate, o-xylene, carbon disulfide, chloroform,
dichloromethane,
tetrahydrofuran, and pentane. Each oil sands sample was weighed and placed in
a cellulose
extraction thimble that was placed on a porous polyethylene support disk in a
jacketed glass
cylinder with a drip rate control valve. Each oil sands sample was then
extracted with a
selected solvent at a selected temperature (10 C or 30 C) in a cyclic contact
and drain
experiment, where the contact time ranged from 15 to 60 minutes. Fresh
contacting solvent
was applied and the cyclic extraction repeated until the fluid drained from
the apparatus
became pale brown in color.
The extracted fluids were stripped of solvent using a rotary evaporator and
thereafter
vacuum dried to remove residual solvent. The recovered bitumen samples all had
residual
solvent present in the range of from 3 wt.% to 7 wt. %. The residual solids
and extraction
thimble were air dried, weighed, and then vacuum dried. Essentially no weight
loss was
observed upon vacuum drying the residual solids, indicating that the solids
did not retain
either extraction solvent or easily mobilized water. Collectively, the weight
of the solid or
sample and thimble recovered after extraction plus the quantity of bitumen
recovered after
extraction divided by the weight of the initial oil sands sample plus the
thimble provide the
mass closure for the extractions. The calculated percent mass closure of the
samples was
slightly high because the recovered bitumen values were not corrected for the
3 wt.% to 7
wt.% residual solvent. The extraction experiment results are summarized in
Table 1.
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Table 1
Summary of Extraction Experiments of Bituminous Oil Sands with Various Fluids
Input Output
Experimental
Extraction Fluid Temperature, Solids Solids Weight
Recovered Weight
C weight, g weight, g
Change, g Bitumen, g Closure, %
Carbon Disulfide 30 151.1 134.74 16.4 16.43 100.0
Carbon Disulfide 10 151.4 134.62 16.8 16.62 99.9
Chloroform 30 153.7 134.3 19.4 18.62 99.5
Chloroform 10 156.2 137.5 18.7 17.85 99.5
Dichloromethane 30 155.8 138.18 17.7 16.30 99.1
Dichloromethane 10 155.2 136.33 18.9 17.66 99.2
o-Xylene 30 156.1 136.58 19.5 17.37 98.6
o-Xylene 10 154.0 136.66 17.3 17.36 100.0
Tetrahydrofuran 30 154.7 136.73 18.0 17.67 99.8
Tetrahydrofuran 10 154.7 136.98 17.7 16.72 99.4
Ethyl Acetate 30 153.5 135.81 17.7 11.46 96.0
Ethyl Acetate 10 155.7 144.51 11.2 10.32 99.4
Pentane 30 154.0 139.11 14.9 13.49 99.1
Pentane 10 152.7 138.65 14.1 13.03 99.3
Dimethyl Sulfide 30 154.2 137.52 16.7 16.29 99.7
Dimethyl Sulfide 10 151.7 134.77 16.9 16.55 99.7
Fig. 7 provides a graph plotting the weight percent yield of extracted bitumen
as a
function of the extraction fluid at 30 C applied with a correction factor for
residual extraction
fluid in the recovered bitumen, and Fig. 8 provides a similar graph for
extraction at 10 C.
Figs. 7 and 8 and Table 1 show that dimethyl sulfide is comparable for
recovering bitumen
from an oil sand material with the best known fluids for recovering bitumen
from an oil sand
material-o-xylene, chloroform, carbon disulfide, dichloromethane, and
tetrahydrofuran-
and is significantly better than pentane and ethyl acetate.
The bitumen samples extracted at 30 C by each solvent were evaluated by SARA
analysis to determine the saturates, aromatics, resins, and asphaltenes
composition of the
bitumen. The results are shown in Table 2.
Table 2
SARA Analysis of Extracted Bitumen Samples as a Function of Extraction Fluid
Oil Composition Normalized Weight Percent
Extraction Fluid Saturates Aromatics Resins
Asphaltenes
Ethyl Acetate 21.30 53.72 22.92 2.05
Pentane 22.74 54.16 22.74 0.36
Dichloromethane 15.79 44.77 24.98 14.45
Dimethyl Sulfide 15.49 47.07 24.25 13.19
Carbon Disulfide 18.77 41.89 25.49 13.85
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o-Xylene 17.37 46.39 22.28 13.96
Tetrahydrofuran 16.11 45.24 24.38 14.27
Chloroform 15.64 43.56 25.94 14.86
The SARA analysis showed that pentane and ethyl acetate were much less
effective
for extraction of asphaltenes from oil sands than are the known highly
effective bitumen
extraction fluids dichloromethane, carbon disulfide, o-xylene,
tetrahydrofuran, and
chloroform. The SARA analysis also showed that dimethyl sulfide has excellent
miscibility
properties for even the most difficult hydrocarbons¨asphaltenes.
The data showed that dimethyl sulfide is generally as good as the recognized
very
good bitumen extraction fluids for recovery of bitumen from oil sands, and is
highly
compatible with saturates, aromatics, resins, and asphaltenes.
EXAMPLE 2
The quality of dimethyl sulfide as an oil recovery agent based on the crude
oil
viscosity lowering properties of dimethyl sulfide was evalulated. Three crude
oils having
widely disparate viscosity characteristics¨an African Waxy crude, a Middle
Eastern
asphaltic crude, and a Canadian asphaltic crude¨were blended with dimethyl
sulfide. Some
properties of the three crudes are provided in Table 3.
Table 3
Crude Oil Properties
African Middle Canadian
Waxy Eastern Asphaltic
crude Asphaltic Crude
crude
Hydrogen (wt.%) 13.21 11.62 10.1
Carbon (wt.%) 86.46 86.55 82
Oxygen (wt.%) na na 0.62
Nitrogen (wt.%) 0.166 0.184 0.37
Sulfur (wt.%) 0.124 1.61 6.69
Nickel (ppm wt.) 32 14.2 70
Vanadium (ppm wt.) 1 11.2 205
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microcarbon residue (wt.%) na 8.50 12.5
C5 Asphaltenes (wt.%) <0.1 na 16.2
C7 Asphaltenes (wt.%) <0.1 na 10.9
Density (g/m1) (15.6 C) 0.88 0.9509 1.01
API Gravity (15.6 C) 28.1 17.3 8.5
Water (Karl Fisher Titration) (wt.%) 1.65 <0.1 <0.1
TAN-E (ASTM D664) (mg KOH/g) 1.34 4.5 3.91
Volatiles Removed by Topping, wt% 21.6 0 0
Saturates in Topped Fluid, wt.% 60.4 41.7 12.7
Aromatics in Topped Fluid, wt.% 31.0 40.5 57.1
Resin in Topped Fluid, wt.% 8.5 14.5 17.1
Asphaltenes in Topped Fluid, wt.% 0.1 3.4 13.1
Boiling Range Distribution
Initial Boiling Point - 204 C (wt.%) 8.5 3.0 0
204 C (400 F) - 260 C (wt.%) 9.5 5.8 1.0
260 C (500 F) - 343 C (wt.%) 16.0 14.0 14.0
343 C (650 F) - 538 C (wt.%) 39.5 42.9 38.0
>538 C (wt.%) 26.5 34.3 47.0
A control sample of each crude was prepared containing no dimethyl sulfide,
and
samples of each crude were prepared and blended with dimethyl sulfide to
prepare crude
samples containing increasing concentrations of dimethyl sulfide. The samples
were heated
to 60 C to dissolve any waxes therein and to permit weighing of a homogeneous
liquid. The
samples were weighed, allowed to cool overnight, then blended with a selected
quantity of
dimethyl sulfide. The samples of the crude/dimethyl sulfide blend were then
heated to 60 C
and mixed to ensure homogeneous blending of the dimethyl sulfide in the
samples. Absolute
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(dynamic) viscosity measurements of each of the samples were taken using a
closed cup
rheometer using a PZ39 rotor sensor assembly in the rheometer. Viscosity
measurements of
each of the samples of the West African waxy crude and the Middle Eastern
asphaltic crude
were taken at 20 C, 40 C, 60 C, 80 C, and then again at 20 C after cooling
from 80 C, where
the second measurement at 20 C is taken to measure the viscosity without the
presence of
waxes since wax formation occurs slowly enough to permit viscosity measurement
at 20 C
without the presence of wax. Viscosity measurements of each of the samples of
the Canadian
asphaltic crude were taken at 5 C, 10 C, 20 C, 40 C, 60 C, 80 C. The measured
viscosities
for each of the crudes are shown in Tables 4, 5, and 6 below.
Table 4
Viscosity (mPa s) of West African Waxy Crude vs. Temperature
at Various levels of Dimethyl Sulfide Diluent
DMS, wt.% 20 C 40 C 60 C 80 C 20 C
0.00 128.8 34.94 15.84 9.59 114.4
1.21 125.8 30.94 14.66 8.92 100.1
2.48 122.3 30.53 13.66 8.44 89.23
5.03 78.37 20.24 10.45 6.55 55.21
7.60 60.92 17.08 9.29 6.09 40.89
9.95 44.70 13.03 7.58 5.04 30.61
15.13 23.96 8.32 4.97 3.38 17.64
19.30 15.26 6.25 4.05 2.92 12.06
Table 5
Viscosity (mPa s) of Middle Eastern Asphaltic Crude vs. Temperature
at Various levels of Dimethyl Sulfide Diluent
DMS, wt.% 20 C 40 C 60 C 80 C 20 C
0.00 2936.3 502.6 143.6 56.6 2922.7
1.3 1733.8 334.5 106.7 44.6 1624.8
2.6 1026.6 219.9 76.5 34.3 881.1
5.3 496.5 134.2 52.2 25.5 503.5
7.6 288.0 89.4 37.4 19.3 290.0
10.1 150.0 52.4 24.5 13.5 150.5
15.2 59.4 25.2 13.6 8.2 60.7
20.1 29.9 14.8 8.7 5.7 31.0
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Table 6
Viscosity (mPa s) of Topped Canadian Asphaltic Crude vs.
Temperature at Various levels of Dimethyl Sulfide Diluent
DMS, wt.% 5 C 10 C 20 C 40 C 60 C 80 C
0.00 579804 28340 3403 732
1.43 212525 14721 2209 538
2.07 134880 10523 1747 427
4.87 28720 3235 985 328
8.01 5799 982 275 106
9.80 2760 571 173 73
14.81 1794 1155 548 159 64 32
19.78 188 69 33 19
29.88 113 81 51 22 13 8
39.61 23 20 14 8 6 4
Figs. 9, 10, and 11 show plots of LogLog(Viscosity)l v. LoglTemperature K1
derived from the measured viscosities in Tables 3, 4, and 5, respectively,
illustrating the
effect of increasing concentrations of dimethyl sulfide in lowering the
viscosity of the crude
samples.
The measured viscosities and the plots show that dimethyl sulfide is effective
for
significantly lowering the viscosity of a crude oil¨particularly high
asphaltene content, high
viscosity, Canadian asphaltenic crude oil¨over a wide range of initial crude
oil viscosities.
EXAMPLE 3
Incremental recovery of oil from a formation core using an oil recovery
formulation
consisting of dimethyl sulfide following oil recovery from the core by water-
flooding was
measured to evaluate the effectiveness of DMS as a tertiary oil recovery
agent.
Two 5.02 cm long Berea sandstone cores with a core diameter of 3.78 cm and a
permeability between 925 and 1325 mD were saturated with a brine having a
composition as
set forth in Table 7.
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TABLE 7
Brine Composition
Chemical component CaC12 MgC12 KC1 NaC1
Na2SO4 NaHCO3
Concentration (kppm) 0.386 0.523 1.478 28.311 0.072 0.181
After saturation of the cores with brine, the brine was displaced by a Middle
Eastern
Asphaltic crude oil having the characteristics as set forth above in Table 3
to saturate the
cores with oil.
Oil was recovered from each oil saturated core by the addition of brine to the
core
under pressure and by subsequent addition of DMS to the core under pressure.
Each core
was treated as follows to determine the amount of oil recovered from the core
by addition of
brine followed by addition of DMS. Oil was initially displaced from the core
by addition of
brine to the core under pressure. A confining pressure of 1 MPa was applied to
the core
during addition of the brine, and the flow rate of brine to the core was set
at 0.05 ml/min.
The core was maintained at a temperature of 50 C during displacement of oil
from the core
with brine. Oil was produced and collected from the core during the
displacement of oil from
the core with brine until no further oil production was observed (24 hours).
After no further
oil was displaced from the core by the brine, oil was displaced from the core
by addition of
DMS to the core under pressure. DMS was added to the core at a flow rate of
0.05 ml/min
for a period of 32 hours for the first core and for a period of 15 hours for
the second core. Oil
displaced from the core during the addition of DMS to the core was collected
separately from
the oil displaced by the addition of brine to the core.
The oil samples collected from each core by brine displacement and by DMS
displacement were isolated from water by extraction with dichloromethane, and
the separated
organic layer was dried over sodium sulfate. After evaporation of volatiles
from the
separated, dried organic layer of each oil sample, the amount of oil displaced
by brine
addition to a core and the amount of oil displaced by DMS addition to the core
were weighed.
Volatiles were also evaporated from a sample of the Middle Eastern asphaltic
oil to be able to
correct for loss of light-end compounds during evaporation. Table 8 shows the
amount of oil
produced from each core by brine displacement followed by DMS displacement.
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TABLE 8
Oil produced Oil produced Oil produced Oil produced
Brine displacement Brine displacement DMS displacement DMS
displacement
(ml) (of % oil initially in (ml) (of % oil
initially
core) in core)
Core 1 4.9 45 3.5 32
Core 2 5.0 45 3.3 30
As shown in Table 8, DMS is quite effective for recovering an incremental
quantity of
oil from a formation core after recovery of oil from the core by waterflooding
with a brine
solution¨recovering approximately 60% of the oil remaining in the core after
the
waterflood.
The present invention is well adapted to attain the ends and advantages
mentioned as
well as those that are inherent therein. The particular embodiments disclosed
above are
illustrative only, as the present invention may be modified and practiced in
different but
equivalent manners apparent to those skilled in the art having the benefit of
the teachings
herein. Furthermore, no limitations are intended to the details of
construction or design
herein shown, other than as described in the claims below. It is therefore
evident that the
particular illustrative embodiments disclosed above may be altered, combined,
or modified
and all such variations are considered within the scope of the present
invention. The
invention illustratively disclosed herein suitably may be practiced in the
absence of any
element that is not specifically disclosed herein and/or any optional element
disclosed herein.
While compositions and methods are described in terms of "comprising,"
"containing," or
"including" various components or steps, the compositions and methods can also
"consist
essentially of' or "consist of' the various components and steps. All numbers
and ranges
disclosed above may vary by some amount. Whenever a numerical range with a
lower limit
and an upper limit is disclosed, any number and any included range falling
within the range is
specifically disclosed. In particular, every range of values (of the form,
"from about a to
about b," or, equivalently, "from approximately a to b," or, equivalently,
"from
approximately a-b") disclosed herein is to be understood to set forth every
number and range
encompassed within the broader range of values. Also, the terms in the claims
have their
plain, ordinary meaning unless otherwise explicitly and clearly defined by the
patentee.
Moreover, the indefinite articles "a" or "an," as used in the claims, are
defined herein to mean
one or more than one of the element that it introduces. If there is any
conflict in the usages of
a word or term in this specification and one or more patent or other documents
that may be
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incorporated herein by reference, the definitions that are consistent with
this specification
should be adopted.
32
